Supplemental Information on Oil and Gas Exploration, Development and Production Activities (Unaudited)

12 Months Ended

Dec. 31, 2018

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information on Oil and Gas Exploration, Development and Production Activities (unaudited)

NOTE 13—SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.

Geographical Data

The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area:

	2018		2017
Revenues
North America	$	2,243,325	$	630,392
South America		—		—
	$	2,243,325	$	630,392
Production Cost
North America	$	914,269	$	216,429
South America		—		—
	$	914,269	$	216,429

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2018, all of which are onshore properties located in the United States and Colombia, South America are summarized below:

	United States			South America			Total
Unproved properties not being amortized	$	135,329		$	2,321,170		$	2,456,499
Proved properties being amortized		10,943,176			49,454,702			60,284,542
Accumulated depreciation, depletion, amortization and impairment		(6,538,195	)		(49,454,702	)		(55,992,897	)
Net capitalized costs	$	4,540,309		$	2,321,170		$	6,861,479

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $5.47 for the United States and $0 for South America for the year ended December 31, 2018.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2018 and 2017 are summarized below:

	2018
	United States		South America
Property acquisition costs:
Proved	$	258,352	$	—
Unproved		135,329		11,829
Exploration costs		71,568		—
Development costs		—		—
Total costs incurred	$	393,681	$	11,829

	2017
	United States		South America
Property acquisition costs:
Proved	$	1,043,977	$	—
Unproved		—		25,154
Exploration costs		3,443,222		—
Development costs		—		—
Total costs incurred	$	4,487,199	$	25,154

Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with reserve estimation and disclosures rules issued by the SEC in 2008. Under those rules, average first-day-of-the-month price during the 12-month period before the end of the year are used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. Disclosures by geographic area include the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The reserve estimates set forth below were prepared by Russell K. Hall and Associates, Inc. (“R.K. Hall”) and Lonquist& Co., LLC (“Lonquist”), utilizing reserve definitions and pricing requirements prescribed by the SEC. R.K. Hall and Lonquist are independent professional engineering firms specializing in the technical and financial evaluation of oil and gas assets. R.K. Hall’s report was conducted under the direction of Russell K. Hall, founder and President of R.K. Hall. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma and is a registered professional engineer with more than 30 years of experience in reserve evaluation services. Lonquist’s report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin and is a registered professional engineer with more than 30 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management. R.K. Hall, Lonquist and their respective employees have no interest in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties.

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

	United States						South America				Total
	Gas (mcf)			Oil (bbls)			Gas (mcf)		Oil (bbls)		Gas (mcf)			Oil (bbls)
Total proved reserves
Balance December 31, 2016		40,020			8,680			—		—		40,020			8,680
Discoveries		2,782,055			389,455			—		—		2,782,055			389,455
Revisions of prior estimates		48,983			3,116			—		—		48,983			3,116
Production		(30,997	)		(10,038	)		—		—		(30,997	)		(10,038	)
Balance December 31, 2017		2,840,061			391,213			—		—		2,840,061			391,213
Revisions to prior estimates		136,932			(16,674	)		—		—		136,932			(16,674	)
Production		(253,053	)		(23,842	)		—		—		(253,053	)		(23,842	)
Balance December 31, 2018		2,723,940			350,697			—		—		2,723,940			350,697
Proved developed reserves
at December 31, 2017		1,666,031			149,088			—		—		1,666,031			149,088
at December 31, 2018		1,544,383			107,548			—		—		1,544,383			107,548
Proved undeveloped reserves
at December 31, 2017		1,174,030			242,125			—		—		1,174,030			242,125
at December 31, 2018		1,179,557			242,949			—		—		1,179,557			242,949

As of December 31, 2018, the Company had proved undeveloped (“PUD”) reserves totaling 242,949 bbls and 1,179,557 mcf. As of December 31, 2017, the Company had PUD reserves totaling 242,125 bbls and 1,174,030 mcf. No PUD reserves were converted to proved developed producing reserves in 2018 or 2017.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

Standardized measure of discounted future net cash flows at December 31, 2018:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	31,125,778		$	—	$	31,125,778
Future production cost		(7,611,052	)		—		(7,611,052	)
Future development cost		(4,758,170	)		—		(4,758,170	)
Future net cash flows		18,756,556			—		18,756,556
10% annual discount for timing of cash flow		(11,041,908	)		—		(11,041,908	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	7,714,648		$	—	$	7,714,648
Changes in standardized measure:
Change due to current year operations Sales, net of production costs	$	(1,465,985	)	$	—	$	(1,465,985	)
Change due to revisions in standardized variables:
Accretion of discount		684,886			—		684,886
Net change in sales and transfer price, net of production costs		1,656,330			—		1,656,330
Revision and others		84,038			—		84,038
Changes in production rates and other		(93,476	)		—		(93,476	)
Net		865,793			—		865,793
Beginning of year		6,848,855			—		6,848,855
End of year	$	7,714,648		$	—	$	7,714,648

Standardized measure of discounted future net cash flows at December 31, 2017:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	27,514,923		$	—	$	27,514,923
Future production cost		(6,628,886	)		—		(6,628,886	)
Future development cost		(4,758,170	)		—		(4,758,170	)
Future net cash flows		16,127,867			—		16,127,867
10% annual discount for timing of cash flow		(9,279,012	)		—		(9,279,012	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	6,848,855		$	—	$	6,848,855
Changes in standardized measure:
Change due to current year operations Sales, net of production costs	$	(413,962	)	$	—	$	(413,962	)
Change due to revisions in standardized variables:
Accretion of discount		16,413			—		16,413
Net change in sales and transfer price, net of production costs		197			—		197
Net change in future development cost		(4,758,170	)		—		(4,758,170	)
Discoveries		6,517,865			—		6,517,865
Revision and others		(57,247	)		—		(57,247	)
Changes in production rates and other		5,379,629			—		5,379,629
Net		6,684,725			—		6,684,725
Beginning of year		164,130			—		164,130
End of year	$	6,848,855		$	—	$	6,848,855